Slurry hydrocracking process using spent hydroprocessing catalyst

ABSTRACT

A slurry hydrocracking process using spent hydroprocessing catalyst is described. The process includes obtaining the spent hydroprocessing catalyst from a hydroprocessing zone; reducing the size of the spent hydroprocessing catalyst; and introducing a heavy hydrocarbon feed and a hydrogen stream into a slurry hydrocracking zone in the presence of the reduced size spent hydroprocessing catalyst under slurry hydrocracking conditions to form a slurry hydrocracking effluent.

BACKGROUND OF THE INVENTION

As the reserves of conventional crude oils decline, heavy oils must beupgraded to meet world demands. In heavy oil upgrading, heaviermaterials are converted to lighter fractions and most of the sulfur,nitrogen and metals must be removed. Heavy oils include materials suchas petroleum crude oil, atmospheric tower bottoms products, vacuum towerbottoms products, heavy cycle oils, shale oils, coal derived liquids,crude oil residuum, topped crude oils and the heavy bituminous oilsextracted from oil sands. These heavy hydrocarbon feedstocks may becharacterized by low reactivity in visbreaking, high coking tendency,poor susceptibility to hydrocracking and difficulties in distillation.Most residual oil feedstocks which are to be upgraded contain some levelof asphaltenes which are typically understood to be heptane insolublecompounds as determined by ASTM D3279 or ASTM D6560. Asphaltenes arehigh molecular weight compounds containing heteroatoms which impartpolarity.

Heavy oils must be upgraded in a primary upgrading unit before they canbe further processed into useable products. Primary upgrading unitsknown in the art include, but are not restricted to, coking processes,such as delayed or fluidized coking, and hydrogen addition processessuch as ebullated bed or slurry hydrocracking (SHC). As an example, theyield of liquid products, at room temperature, from the coking of someCanadian bitumens is typically about 55 to 60 wt-% with substantialamounts of coke as by-product. On similar feeds, ebullated bedhydrocracking typically produces liquid yields of 50 to 55 wt-%. U.S.Pat. No. 5,755,955 describes an SHC process which has been found toprovide liquid yields of 75 to 80 wt-% with much reduced coke formationthrough the use of additives.

In SHC, a three-phase mixture of heavy liquid oil feed cracks in thepresence of gaseous hydrogen over solid catalyst to produce lighterproducts under pressure at an elevated temperature. Iron sulfate hasbeen disclosed as an SHC catalyst, for example, in U.S. Pat. No.5,755,955.

During an SHC reaction, it is important to minimize coking Asphaltenespresent as a byproduct from the SHC reaction product can, if not managedproperly, self-associate, or flocculate to form larger molecules,generate a mesophase and precipitate out of solution to form coke.Mesophase formation is a critical reaction constraint in SHC reactions.

The catalysts for SHC are typically iron based. These iron basedcatalysts have lower hydrogenation activity than molybdenum basedcatalysts. Currently, the SHC reactions are thermal in nature with cokesuppression being the target of the catalyst.

The addition rate to obtain the same hydrogenation activity insuppressing coke formation with the molybdenum-containing catalyst istherefore much lower than what is required for bauxite or ferroussulfate catalyst.

However, molybdenum is an expensive metal and when used in ppmquantities as a bulk metal slurry catalyst, recovery is not efficient.Sustainable molybdenum management would improve the economics associatedwith using molybdenum catalyst.

U.S. Pat. No, 8,617, 955 described an SHC catalyst comprising molybdenumimpregnated onto alumina. When this catalyst was charged to the reactionat a 300 wppm concentration in hydrocarbon, it provided equivalentactivity to an iron catalyst while greatly lowering the amount of solidscirculating through the reactor. The base provided bulk to themolybdenum catalyst allowing easier recycle and/or recovery. Inaddition, alumina in the base greatly suppressed formation of mesophasewhich leads to coke.

Although the catalyst described in U.S. Pat. No. 8,617, 955 iseconomically viable, it would be desirable to obtain a less expensive,yet effective molybdenum catalyst for SHC processes.

SUMMARY OF THE INVENTION

One aspect of the invention is a slurry hydrocracking process usingspent hydroprocessing catalyst process. In one embodiment, the processincludes obtaining the spent hydroprocessing catalyst from ahydroprocessing zone; reducing the size of the spent hydroprocessingcatalyst; and introducing a heavy hydrocarbon feed and a hydrogen streaminto a slurry hydrocracking zone in the presence of the reduced sizespent hydroprocessing catalyst under slurry hydrocracking conditions toform a slurry hydrocracking effluent.

In another embodiment, the process involves obtaining the spenthydroprocessing catalyst from a hydroprocessing zone, wherein the spenthydroprocessing catalyst has at least one of: a metals content of atleast about 10 wt %; a crushing strength of less than about 4 lbs; arelative weight activity of less than about 80% of a relative weightactivity of an initial hydroprocessing catalyst; or a surface area ofless than about 80% of a surface area of the initial hydroprocessingcatalyst; and introducing a heavy hydrocarbon feed and a hydrogen streaminto a slurry hydrocracking zone in the presence of the spenthydroprocessing catalyst under slurry hydrocracking conditions to form aslurry hydrocracking effluent.

BRIEF DESCRIPTION OF THE DRAWING

The FIGURE illustrates one embodiment of a SHC process.

DETAILED DESCRIPTION OF THE INVENTION

The present invention provides a slurry hydrocracking (SHC) processemploying an effective but less expensive molybdenum catalyst. Thecatalyst is a spent hydroprocessing catalyst which is ground to aparticle size of less than 500 μm.

As used herein, the term “boiling point temperature” means atmosphericequivalent boiling point (AEBP) as calculated from the observed boilingtemperature and the distillation pressure, as calculated using theequations furnished in ASTM D1160 appendix A7 entitled “Practice forConverting Observed Vapor Temperatures to Atmospheric EquivalentTemperatures”.

As used herein, “pitch” means the hydrocarbon material boiling aboveabout 524° C. (975° F.) AEBP as determined by any standard gaschromatographic simulated distillation method such as ASTM D2887, D6352or D7169, all of which are used by the petroleum industry.

As used herein, “heavy vacuum gas oil” (HVGO) means the hydrocarbonmaterial boiling in the range between about 427° C. (800° F.) and about524° C. (975° F.).

As used herein, “light vacuum gas oil” (LVGO) means the hydrocarbonmaterial boiling in the range between about 343° C. (650° F.) and about427° C. (800° F.).

As used herein, solvent “insolubles” means materials not dissolving inthe solvent named.

As used herein, “TIOR” is the toluene-insoluble organic residue whichrepresents non-catalytic solids in the product part boiling over 524° C.

As used herein, “mesophase” is a component of TIOR that signifies theexistence of coke, another component of TIOR. Mesophase is asemi-crystalline carbonaceous material defined as round, anisotropicparticles present in pitch. The presence of mesophase can serve as awarning that operating conditions are too severe in an SHC and that cokeformation is likely to occur under prevailing conditions.

As used herein, “mean particle or crystallite diameter” is understood tomean the same as the average particle or crystallite diameter and iscalculated for all of the particles or crystallites fed to the reactorwhich may be determined by a representative sampling, respectively.

As used herein, “about” is understood to mean within 10% of the value,or within 5%, or within 1%.

Hydroprocessing is a process that uses a hydrogen-containing gas withsuitable catalyst(s) for a particular application. In many instances,hydroprocessing is generally accomplished by contacting the selectedfeedstock in a reaction vessel or zone with the suitable catalyst underconditions of elevated temperature and pressure in the presence ofhydrogen. It includes hydrotreating and hydrocracking Hydrotreating is aprocess in which hydrogen gas is contacted with a hydrocarbon stream inthe presence of suitable catalysts which are primarily active for theremoval of heteroatoms, such as sulfur, nitrogen, and metals from thehydrocarbon feedstock. In hydrotreating, hydrocarbons with double andtriple bonds may be saturated.

Hydrotreating catalyst deactivates with use in the hydrotreating processand may be replaced after a single cycle or it may be regenerated andreused in the hydrotreating process multiple times, until sufficientactivity can no longer be recovered by the regeneration procedure.Surprisingly, the deactivated hydrotreating catalyst is stillsufficiently active to be a viable catalyst in the slurry hydrocrackingprocess.

One common type of hydrotreating catalysts includes at least one GroupVIII metal (preferably iron, cobalt or nickel, more preferably cobaltand/or nickel) and at least one Group VI metal (preferably molybdenum ortungsten) on a high surface area support material, preferably alumina.The Group VIII metal is typically present in an amount ranging fromabout 1 to about 20 weight percent, or about 2 to about 12 weightpercent, or about 2 to about 5 weight percent. The Group VI metal willtypically be present in an amount ranging from about 1 to about 25weight percent, or about 2 to about 25 weight percent, or 5 to about 20weight percent. The support materials are typically metal oxides,including, but not limited to, alumina, silica, titania, zirconia, ormixtures thereof.

Hydrocracking is a type of hydroprocessing that is generallyaccomplished by contacting in a hydrocracking reaction vessel or zones agas oil or other feedstock to be treated with a suitable hydrocrackingcatalyst under conditions of elevated temperature and pressure in thepresence of hydrogen so as to yield a product containing a distributionof lower-boiling point hydrocarbon products desired by the refiner. Theoperating conditions and the hydrocracking catalysts within ahydrocracking reactor influence the yield of the hydrocracked products.

In some embodiments, the hydrocracking catalysts utilize amorphous basesor low-level zeolite bases combined with one or more Group VIII or GroupVI metal hydrogenating components. In other embodiments, thehydrocracking catalyst comprises, in general, any crystalline zeolitecracking base upon which is deposited a minor proportion of a Group VIIImetal hydrogenating component. Additional hydrogenating components maybe selected from Group VI for incorporation with the zeolite base. Thezeolite cracking bases are sometimes referred to in the art as molecularsieves and are usually composed of silica, alumina and one or moreexchangeable cations such as sodium, magnesium, calcium, rare earthmetals, etc. They are further characterized by crystal pores ofrelatively uniform diameter between about 4 and 14 Angstroms (10⁻¹⁰meters). It is preferred to employ zeolites having a relatively highsilica/alumina mole ratio between about 3 and 12. Suitable zeolitesfound in nature include, for example, mordenite, stilbite, heulandite,ferrierite, dachiardite, chabazite, erionite and faujasite. Suitablesynthetic zeolites include, for example, the B, X, Y and L crystaltypes, e.g., synthetic faujasite and mordenite. The preferred zeolitesare those having crystal pore diameters between about 8-12 Angstroms(10⁻¹⁰ meters), wherein the silica/alumina mole ratio is about 4 to 6.Examples of preferred zeolites include synthetic Y molecular sieve andbeta zeolite. The active metals employed in the preferred hydrocrackingcatalysts of the present invention as hydrogenation components are thoseof Group VIII, i.e., iron, cobalt, nickel, ruthenium, rhodium,palladium, osmium, iridium and platinum. In addition to these metals,other promoters may also be employed in conjunction therewith, includingthe metals of Group VI, e.g., molybdenum and tungsten. The amount ofhydrogenating metal in the catalyst can vary within wide ranges. Broadlyspeaking, any amount between about 0.05 percent and 30 percent by weightmay be used. In the case of the noble metals, it is normally preferredto use about 0.05 to about 2 wt-%. The preferred method forincorporating the hydrogenating metal is to contact the zeolite basematerial with an aqueous solution of a suitable compound of the desiredmetal wherein the metal is present in a cationic form. Followingaddition of the selected hydrogenating metal or metals, the resultingcatalyst powder is then filtered, dried, pelleted with added lubricants,binders or the like if desired, and calcined in air at temperatures of,e.g., 371° C. to 649° C. (700° F. to 1200° F.) in order to activate thecatalyst and decompose ammonium ions. Alternatively, the zeolitecomponent may first be pelleted, followed by the addition of thehydrogenating component and activation by calcining The catalysts may beemployed in a hydroprocessing reactor in undiluted form, or the powderedzeolite catalyst may be mixed and copelleted with other relatively lessactive catalysts, diluents or binders such as alumina, silica gel,silica-alumina cogels, activated clays and the like in proportionsranging between 5 and 90 wt-%. These diluents may be employed as such orthey may contain a minor proportion of an added hydrogenating metal suchas a Group VI and/or Group VIII metal.

There are various ways to evaluate a hydroprocessing catalyst fordeactivation. One method involves determining the total metals contentof the catalyst. When the total metal content is at least about 10%, thehydroprocessing catalyst may need to be replaced. The metals includenickel, vanadium, iron, silicon, sodium, potassium, calcium, magnesium,arsenic, and lead.

Another method of evaluating whether a hydroprocessing catalyst is spentis to determine the crush strength of the hydroprocessing catalyst. Whenthe crush strength after regeneration is less than about 20 N, thehydroprocessing catalyst may need to be replaced. Crush strength can bemeasured using ASTM D4179, for example.

Still another method involves determining the relative weight activityor relative volume activity of the spent catalyst after regenerationcompared to the initial hydroprocessing catalyst. The activity can befor desulfurization, denitrification, or demetallation. When the weightactivity or the volume activity is less than about 80% of the initialweight or volume activity, the hydroprocessing catalyst may need to bereplaced. Relative weight and relative volume activity are known tests,which are described in EP 2486109, for example.

Another indicator that the hydroprocessing catalyst may need to bereplaced is the surface area of the spent catalyst. When the surfacearea of the spent catalyst after regeneration is less than about 80% ofthe surface area of the initial catalyst, the hydroprocessing catalystmay need to be replaced. The surface area is typically determined bynitrogen adsorption—for example, by the method of Brunauer, Emmett, andTeller (J. Am. Chem. Soc. v.60, p.309).

Currently, most of the spent hydroprocessing catalyst is not sent formetals recovery because the value of the metals does not justify thecost of recovery (except for noble metals). In many cases, the spenthydroprocessing catalyst is sent to landfills, with refiners paying forthe disposal. By utilizing the spent hydroprocessing catalyst in the SHCprocess, the disposal cost can be reduced, and there is a ready sourceof material to be used in the SHC process. As a result, the cost of themolybdenum catalyst is reduced significantly.

The spent hydroprocessing catalyst may have a particle diameter of about1-3 mm for spheres or lobed cross-section materials and up to about 10mm of length for extrudates. It was determined that this is typicallytoo abrasive to be used in some SHC equipment. Therefore, the spenthydroprocessing catalyst is reduced in size to an average particle sizeof less than about 500 μm, or less than about 400 μm, or less than about300 μm, or less than about 200 μm, or less than about 100 μm, or lessthan about 75 μm, or less than about 50 μm, or less than about 40 μm, orless than about 30 μm, or less than about 20 μm, or less than about 15μm, or less than about 10 μm, or less than about 5 μm, or less thanabout 1 μm. Although particles of less than about 1 can be used, it maybe difficult to remove them from the slurry hydrocracking effluent usingsome processes such as a decanter. However, other recovery processessuch as centrifuges could be used to recover particles smaller than 1

The particle size can be reduced using any suitable process including,but not limited to, grinding, ball milling, or jet milling. Wet ballmilling is particularly advantageous because it combines the steps ofgrinding and slurrying the catalyst with the feedstock into a singleprocess step. The processes used to reduce the size of the spenthydroprocessing catalyst may improve activity by exposing pores that areblocked by metals and coke deposits in the spent catalyst.

The spent hydroprocessing catalyst is recovered from a hydroprocessingzone, and reduced in size. The reduced size spent hydroprocessingcatalyst is then used as the catalyst in the SHC zone.

In the exemplary SHC process as shown in the Figure, one, two or all ofa heavy hydrocarbon oil feed in line 8, a recycle pitch streamcontaining catalyst particles in line 39, and recycled HVGO in line 37may be combined in line 10. The combined feed in line 10 is heated inthe heater 32 and pumped through an inlet line 12 into an inlet in thebottom of the tubular SHC reactor 13.

The reduced size spent hydroprocessing catalyst can be added to one ormore of the heavy hydrocarbon oil feed in line 8, the recycle pitchstream in line 39, and the recycled HVGO in line 37. The catalyst ispresent in an amount sufficient to achieve a concentration of molybdenumor tungsten in the combined stream of about 30 wppm to about 500 wppm,or about 30 wppm to about 400 wppm, or about 30 wppm to about 300 wppm,or about 30 wppm to about 250 wppm, or about 30 wppm to about 200 wppm,or about 30 wppm to about 150 wppm, or about 30 wppm to about 100 wppm.For example, if the spent catalyst contains 5 wt % molybdenum and thedesired level is 500 wppm, about 1 wt % ground catalyst would be needed.If the spent catalyst contains 16% molybdenum and the desired level is30 wppm, then about 200 wppm ground catalyst would be needed.

The heavy hydrocarbon oil feed to the process often comprises a vacuumcolumn residual stream from a distillation column bottoms stream, suchas with an initial boiling point from about 524+° C. (975+° F.), anatmospheric column residual stream, a visbreaker pitch stream, a fluidcatalytic cracking main column bottoms stream (also called clarifiedslurry oil), and solvent deasphalted oil pitch. Other representativecomponents, as fresh hydrocarbon feeds, that may be included in theheavy hydrocarbon feedstock include gas oils, such as straight-run gasoils (e.g., vacuum gas oil), recovered by fractional distillation ofcrude petroleum. Other gas oils produced in refineries include coker gasoil and visbreaker gas oil. In the case of a straight-run vacuum gasoil, the distillation end point is governed by the crude oil vacuumfractionation column and particularly the fractionation temperaturecutoff between the vacuum gas oil and vacuum column bottoms split. Thus,refinery gas oil components suitable as fresh hydrocarbon feedcomponents of the heavy hydrocarbon feedstock to the SHC reactor, suchas straight-run fractions, often result from crude oil fractionation ordistillation operations, while other gas oil components are obtainedfollowing one or more hydrocarbon conversion reactions. Whether or notthese gas oils are present, the combined heavy hydrocarbon feedstock tothe SHC reaction zone can be a mixture of hydrocarbons (i) boilingpredominantly in a representative crude oil vacuum column residue range,for example above about 538° C. (1000° F.), and (ii) hydrocarbonsboiling in a representative gas oil range, for example from about 343°C. (650° F.) to an end point of about 593° C. (1100° F.), with otherrepresentative distillation end points being about 566° C. (1050° F.),about 538° C. (1000° F.), and about 482° C. (900° F.). In this case,components (i) and (ii) of the heavy hydrocarbon feedstock are thereforerepresentative of a crude oil vacuum column residue and asphalt from asolvent deasphalting unit (also called pitch), respectively.

Additional components of the heavy hydrocarbon feed can include residualoils such as a crude oil vacuum distillation column residuum boilingabove 566° C. (1050° F.), tars, bitumen, coal oils, and shale oils.Other asphaltene-containing materials such as whole or topped petroleumcrude oils including heavy crude oils may also be used as componentsprocessed by SHC. In addition to asphaltenes, these further possiblecomponents of the heavy hydrocarbon feedstock, as well as others,generally also contain significant metallic contaminants (e.g., nickel,iron and vanadium), a high content of organic sulfur and nitrogencompounds, and a high Conradson carbon residue. The metals content ofsuch components, for example, may be 100 ppm to 1,000 ppm by weight, thetotal sulfur content may range from 1% to 7% by weight, and the APIgravity may range from about −5° to about 35°. The Conradson carbonresidue of such components is generally at least about 5%, and is oftenfrom about 10% to about 35% by weight.

The reduced size spent hydroprocessing catalyst may be added directly tothe combined heavy hydrocarbon oil feed to the SHC reactor 13 from line10 or may be mixed with another heavy hydrocarbon oil feed in lines 8,37, or 39 before they are combined in line 10 and enter the reactor 13as a slurry. Many mixing and pumping arrangements may be suitable. It isalso contemplated that feed streams may be added separately to the SHCreactor 13.

Recycled hydrogen and make up hydrogen from line 30 are fed into the SHCreactor 13 through line 14 after undergoing heating in heater 31.Hydrocarbon feed from line 10 may be combined with the recycled hydrogenand make up hydrogen in line 14. The hydrogen in line 14 that is notpremixed with feed may be added at one or more locations above the feedentry in line 12. Both feed from line 12 and hydrogen in line 14 may bedistributed in the SHC reactor 13 with an appropriate distributor.Additionally, hydrogen may be added to the feed in line 10 before it isheated in heater 32 to prevent deposits in the heater 32 and deliveredto the SHC reactor in line 12. Hydrogen can be added in lines 6 and 6′to cool the reactor and control the reactor temperature profile.

Preferably the recycled pitch stream in line 39 makes up in the range ofabout 5 to about 15 wt-% of the feedstock to the SHC reactor 13, whilethe HVGO in line 37 makes up in the range of 5 to 50 wt-% of thefeedstock, depending upon the quality of the feedstock and theonce-through conversion level.

The feed entering the SHC reactor 13 comprises three phases, solidcatalyst particles, vaporous, liquid and solid hydrocarbon feed andgaseous hydrogen.

The SHC process can be operated at quite moderate pressure, in the rangeof 3.5 to 27.6 MPa (500 to 4000 psig) and preferably in the range of10.3 to 17.2 MPa (1500 to 2800 psig), without coke formation in the SHCreactor 13. The reactor temperature is typically in the range of about400° C. to about 500° C. with a temperature of about 410° C. to about475° C. being suitable and a range of 425° C. to 460° C. beingpreferred. The LHSV is typically below about 4 h⁻¹ on a fresh feedbasis, with a range of about 0.1 to 3 h⁻¹ being preferred and a range ofabout 0.1 to 1 h⁻¹ being particularly preferred.

Although SHC can be carried out in a variety of known reactors of eitherup or downflow, it is particularly well suited to a tubular reactorthrough which feed, catalyst and gas move upwardly. Hence, the outletfrom SHC reactor 13 is above the inlet. Although only one is shown inthe Figure, one or more SHC reactors 13 may be utilized in parallel orin series.

Because the liquid feed is converted to vaporous product, foaming tendsto occur in the SHC reactor 13. An antifoaming agent may also be addedto the SHC reactor 13, preferably to the top thereof, to reduce thetendency to generate foam. Suitable antifoaming agents include siliconesas disclosed in U.S. Pat. No. 4,969,988.

A gas-liquid mixture is withdrawn from the top of the SHC reactor 13through line 15 and separated. The separation preferably takes place ina hot, high-pressure separator 20 kept at a separation temperaturebetween about 200° C. and 470° C. (392° F. and 878° F.) and preferablyat about the pressure of the SHC reactor. In the hot separator 20, theeffluent from the SHC reactor 13 is separated into a liquid stream 16and a gaseous stream 18. The liquid stream 16 contains HVGO. The gaseousstream 18 comprises between about 35 and 80 vol-% of the hydrocarbonproduct from the SHC reactor 13 and is further processed to recoverhydrocarbons and hydrogen for recycle.

A liquid portion of the product from the hot separator 20 may be used toform the recycle stream to the SHC reactor 13 after separation which mayoccur in a liquid vacuum fractionation column 24. Line 16 introduces theliquid fraction from the hot high pressure separator 20 to a liquidvacuum fractionation column 24, which is preferably a vacuumdistillation column. The liquid vacuum fractionation column 24 istypically maintained at a pressure between about 1.7 and 10.0 kPa (0.25and 1.5 psi) and at a vacuum distillation temperature resulting in anatmospheric equivalent cut point between LVGO and HVGO of between about250° C. and 500° C. (482° F. and 932° F.). Three fractions may beseparated in the liquid fractionation column 24: an overhead fraction ofLVGO in an overhead line 38 which may be further processed, a HVGOstream from a side cut in line 29, and a pitch stream obtained in abottoms line 40 which typically boils above 450° C. At least a portionof this pitch stream may be recycled back in line 39 to form part of thefeed slurry to the SHC reactor 13. Remaining catalyst particles from SHCreactor 13 will be present in the pitch stream in lines 39 and 41.

A filtration device 42 such as a centrifuge, a sieve device or othersuitable means may separate catalyst particles from pitch at temperatureof about 250° C. to about 350° C. A sieve device is illustrated as thefiltration device 42. In the filtration device 42, catalyst particles donot permeate a sieve 43, but are returned in line 44 to the recyclepitch line 39 to reenter the reactor with the recycled pitch. Filteredpitch with very little catalyst loading is removed from the filtrationdevice 42 in line 45. Any remaining portion of the pitch stream isrecovered in line 46.

During the SHC reaction, it is important to minimize coking Adding alow-polarity aromatic oil to the feedstock reduces coke production. Thepolar aromatic material may come from a wide variety of sources. Aportion of the HVGO containing polar aromatic material in line 29 may berecycled by line 37 to form part of the feed slurry to the SHC reactor13. The remaining portion of the HVGO may be recovered in line 35.

The gaseous stream in line 18 may be combined with the overhead fractionof LVGO from the overhead line 38 and may be delivered to a cool, highpressure separator 19. Within the cool separator 19, the product isseparated into a gaseous stream rich in hydrogen which is drawn offthrough the overhead in line 22 and a liquid hydrocarbon product whichis drawn off the bottom through line 28.

The hydrogen-rich stream 22 may be passed through a packed scrubbingtower 23 where it is scrubbed by means of a scrubbing liquid in line 25to remove hydrogen sulfide and ammonia. The spent scrubbing liquid inline 27 may be regenerated and recycled and is usually an amine. Thescrubbed hydrogen-rich stream emerges from the scrubber via line 34 andis combined with fresh make-up hydrogen added through line 33 andrecycled through a recycle gas compressor 36 and line 30 back to reactor13.

The bottoms line 28 may carry liquid SHC product to a productfractionator 26. The liquid SHC product may be stripped in a strippingcolumn before entering the product fractionator 26 to remove hydrogensulfide. The product fractionator 26 may comprise one or several vesselsalthough it is shown only as one in the Figure. The product fractionatorproduces a C₄-stream recovered in overhead line 52, a naphtha productstream in line 54, a diesel stream in line 56 and a light vacuum gas oil(LVGO) stream in bottoms line 58.

While at least one exemplary embodiment has been presented in theforegoing detailed description of the invention, it should beappreciated that a vast number of variations exist. It should also beappreciated that the exemplary embodiment or exemplary embodiments areonly examples, and are not intended to limit the scope, applicability,or configuration of the invention in any way. Rather, the foregoingdetailed description will provide those skilled in the art with aconvenient road map for implementing an exemplary embodiment of theinvention. It being understood that various changes may be made in thefunction and arrangement of elements described in an exemplaryembodiment without departing from the scope of the invention as setforth in the appended claims.

What is claimed is:
 1. A slurry hydrocracking process using spenthydroprocessing catalyst comprising: obtaining the spent hydroprocessingcatalyst from a hydroprocessing zone; reducing the size of the spenthydroprocessing catalyst; and introducing a heavy hydrocarbon feed and ahydrogen stream into a slurry hydrocracking zone in the presence of thereduced size spent hydroprocessing catalyst under slurry hydrocrackingconditions to form a slurry hydrocracking effluent.
 2. The process ofclaim 1 wherein the spent hydroprocessing catalyst comprises at leastone Group VIII metal and at least one Group VI metal on a support. 3.The process of claim 2 wherein the at least one Group VIII metalcomprises iron, cobalt, and nickel, wherein the Group VI metal comprisesmolybdenum and tungsten, and wherein the support comprises a metaloxide.
 4. The process of claim 1 wherein the spent hydroprocessingcatalyst comprises at least one Group VIII or Group VI metals on anamorphous base or a zeolite base.
 5. The process of claim 4 wherein theat least one Group VIII metal comprises iron, cobalt, and nickel,wherein the Group VI metal comprises molybdenum and tungsten, andwherein the zeolite base comprises alumina and silica.
 6. The process ofclaim 1 wherein the reduced size spent hydroprocessing catalyst ispresent in an amount of about 200 wppm to about 1 wt %.
 7. The processof claim 1 wherein reducing the size of the spent hydroprocessingcatalyst comprises one or more of grinding the spent hydroprocessingcatalyst, ball milling the spent hydroprocessing catalyst, and jetmilling the spent hydroprocessing catalyst.
 8. The process of claim 1wherein the reduced size spent hydroprocessing catalyst has an averagesize of less than 500 μm.
 9. The process of claim 1 wherein the reducedsize spent hydroprocessing catalyst has an average size of less than 100μm.
 10. The process of claim 1 further comprising recovering the reducedsize spent hydroprocessing catalyst from the slurry hydrocrackingeffluent.
 11. The process of claim 10 further comprising recycling therecovered catalyst.
 12. A slurry hydrocracking process using spenthydroprocessing catalyst comprising: obtaining the spent hydroprocessingcatalyst from a hydroprocessing zone, the spent hydroprocessing catalystcomprising at least one Group VIII metal and at least one Group VI metalon a support or at least one Group VIII or Group VI metals on anamorphous base or a zeolite base; grinding the spent hydroprocessingcatalyst to reduce the size of the spent hydroprocessing catalyst toless than 500 μm; and introducing a heavy hydrocarbon feed and ahydrogen stream into a slurry hydrocracking zone in the presence of theground spent hydroprocessing catalyst under slurry hydrocrackingconditions to form a slurry hydrocracking effluent.
 13. The process ofclaim 12 wherein the at least one Group VIII metal comprises iron,cobalt, and nickel and wherein the Group VI metal comprises molybdenumand tungsten, and wherein the support comprises a metal oxide.
 14. Theprocess of claim 13 wherein the metal oxide comprises alumina, silica,titania, zirconia, or mixtures thereof.
 15. The process of claim 12wherein the at least one Group VIII metal comprises iron, cobalt, andnickel, wherein the Group VI metal comprises molybdenum and tungsten,and wherein the zeolite base comprises alumina and silica.
 16. Theprocess of claim 12 wherein the reduced size spent hydroprocessingcatalyst is present in an amount of about 30 wppm to about 100 wppm. 17.The process of claim 12 wherein the ground spent hydroprocessingcatalyst has an average size of less than 500 μm.
 18. The process ofclaim 12 wherein the ground spent hydroprocessing catalyst has anaverage size of less than 100 μm.
 19. The process of claim 12 furthercomprising recovering the ground spent hydroprocessing catalyst from theslurry hydrocracking effluent.
 20. A slurry hydrocracking process usingspent hydroprocessing catalyst comprising: obtaining the spenthydroprocessing catalyst from a hydroprocessing zone, wherein the spenthydroprocessing catalyst has at least one of: a metals content of atleast about 10 wt %; a crushing strength after regeneration of less thanabout 20 N; a weight activity after regeneration of less than about 80%of a weight activity of an initial hydroprocessing catalyst or a volumeactivity after regeneration of less than about 80% of a volume activityof the initial hydroprocessing catalyst; or a surface area afterregeneration of less than about 80% of a surface area of the initialhydroprocessing catalyst; and introducing a heavy hydrocarbon feed and ahydrogen stream into a slurry hydrocracking zone in the presence of thespent hydroprocessing catalyst under slurry hydrocracking conditions toform a slurry hydrocracking effluent.